Heat generating systems with furnaces for firing fossil fuels have long been employed to generate controlled heat, with the objective of doing useful work. The work might be in the form of direct work, as with kilns, or might be in the form of indirect work, as with steam generators for industrial or marine applications or for driving turbines that produce electric power. During the combustion process, the sulfur in the fuel is oxidized to form SO2, which is exhausted in the flue gas leaving the furnace
An air pollution control (APC) subsystem is conventionally used to remove SO2 and other so called pollutants, such as NOx and particulate matter including flyash, from SO2 laden flue gas produced by such heat generating systems. Conventionally, the flue gas exhausted from the furnace of a coal fired heat generation system is directed to the APC subsystem. Commonly the flue gas entering the APC subsystem is directed to APC components, each of which can be considered a system in its own right, in order remove the SO2 and other so called pollutants from the flue gas. For example, the flue gas may be processed via a selective catalytic reduction (SCR) system (not shown) to remove NOx and via a dry or semi-dry SO2 scrubber system, such as a flash dryer absorber (FDA), to remove SO2 and particulate matter.
FIG. 1 depicts an FDA 10 for scrubbing SO2 from the flue gas produced in the burning of fossil fuel. As shown, the SO2 laden flue gas 12 is processed by an absorber tower 14 to capture the SO2 in the SO2 laden flue gas. As will be understood by those skilled in the art, the SO2 in the flue gas has a high acid concentration. Accordingly, to capture the SO2, the absorber tower 14 creates an environment in which the SO2 laden flue gas is placed in contact, under the proper conditions, with material having a higher pH level than that of the flue gas in order to capture, i.e. absorb, the SO2 from the SO2 laden flue gas, so that a desulfurization of the flue gas will occur. To accomplish this, the residual content of calcium oxide (CaO), which is commonly referred to as lime, in the flyash within the flue gas can be used as the sorbent. Accordingly, during processing, conditions are established in the absorber tower 14 such that the SO2 in the SO2 laden flue gas 12 is absorbed by the residual CaO in the flyash. This transforms the residual CaO into calcium sulfite CaSO3, which is basically a salt.
The flue gas 12a, which includes the flyash with the transformed sorbent, is exhausted from the absorber tower 14 to a baghouse 16 or alternatively an electrostatic precipitator (ESP) (not shown). The baghouse 16 is shown with an air slide bottom 18. The baghouse 16 functions to separate the flyash from the flue gas 12a, to thereby remove the flyash with the absorbed SO2 from the flue gas 12c that flows downstream of the baghouse. From the baghouse 16, the flue gas 12c can, if desired, be directed to downstream processing equipment (not shown), but will ultimately be directed to an exhaust stack (also not shown). Beneficially, at least a portion of the separated flyash 12b is directed from the baghouse 16, via a feeder 20, depicted as a rotary feeder, driven by motor 22, for recycling. The feeder 20 directs the flyash 12b to a hydrator 25, depicted as including a mixer 24 driven by motor 26, where it is partially hydrated, i.e. humidified, with water (H2O), before being recycled back, via hydrated stream 28 to the absorber tower 14. It will be recognized that fresh lime may also be added to the flyash in the mixer to maintain an appropriate pH of the recycled flyash entering the absorber. Any non-recycled flyash is directed from the baghouse 16 via waste stream 30 to a flyash disposal area 32.
It is generally recognized that increasing the humidity of the and flue gas in the absorber tower 14 will improve the efficiency at which the recycled flyash captures the SO2 from the SO2 laden flue gas. However, conventionally, the maximum relative humidity of the stream 28 entering the absorber tower 14 is maintained within a range of forty percent (40%) to fifty percent (50%) in order to avoid flyash handling problems, binding in the baghouse 16 or ESP (not shown), and cold spot condensation problems, even though this might be lower than the humidity level which would be most preferred from the standpoint of efficient capture of the SO2.
In summary, conventionally the SO2 within the SO2 laden flue gas is absorbed by the flyash in an absorber tower. The flyash with absorbed SO2 is then separated from the flue gas by a baghouse or ESP, and at least a part of the separated fly ash is feed to a hydrator and rehydrated to a less than desirable humidity level for SO2 capture, before being recycled back to the absorber tower.
Accordingly, a need exists for a technique that will facilitate capturing and removing SO2 from SO2 laden flue gasses, without the limitations of conventional techniques.